The present invention relates to the recovery of mineral resources from solid materials containing the same and apparatus therefor. In a more specific aspect, the present invention relates to the in situ recovery of mineral resources from subsurface earth formations containing the same and apparatus therefor.
Mineral resources broadly cover native, nonorganic or fossilized organic substances contained in the earth's crust and, in most cases, in subsurface earth formations. The fossilized organic substances, such as petroleum, tars, asphalts, kerogen, coal, etc., particularly petroleum and nonorganic minerals such as uranium, vanadium, thorium, gold, rare earth metals, etc., particularly uranium, are in great demand and quite valuable and therefore, it is important that methods and apparatus for the recovery thereof maximize the amount recovered, while at the same time simplifying and reducing the cost of such recovery.
Oil exists in subterranean formations or reservoirs in a wide variety of forms, in a wide variety of formations and under a wide variety of natural conditions. In most cases natural forces present in the reservoir permit the production of significant amounts of the oil by so-called primary recovery methods. Usually this is brought about by the fact that reservoir pressure, supplied by gas under pressure, either in solution in the oil or as a gas cap, water, etc. is sufficient to force the oil to the surface of the earth. In any event, these so-called primary recovery methods are capable of recovering only minor portions of the original oil in place due to depletion of the natural forces and other factors. In some cases, little or none of the oil can be produced by natural forces. Accordingly, a wide variety of supplemental or artifical recovery techniques have been employed and still more have been proposed in order to increase the recovery of oil from subterranean formations. If the artifical recovery technique is utilized in reservoirs having insufficient natural production forces it is often referred to as primary recovery and, if used immediately following discontinuance of primary recovery methods, such technique has been referred to as a secondary recovery technique. If a so-called secondary recovery technique is followed by another artifical recovery technique, the latter has often been referred to as tertiary recovery. However, the lines of demarcation among these three techniques have been obliterated to a certain extent and it is, therefore, best to refer to all such artifical recovery techniques, whether primary, secondary or tertiary, as "enhanced oil recovery" techniques. Irrespective of the name applied to the recovery technique, all such enhanced oil recovery techniques include the injection of a gaseous or a liquid fluid into one or more injection wells under a pressure sufficient to displace or drive at least a portion of the oil from the reservoir, i.e. above the reservoir pressure, and producing the thus displaced oil from one or more producing wells. Obviously, a wide variety of driving fluids or injection fluids and combinations thereof have been proposed. However, the basic drive fluids or injection fluids include air, natural gas, carbon dioxide, propane, steam, water, surfactants and polymers. Unfortunately, none of these materials is an ideal displacement fluid due to a number of factors which affect the amount of oil which can be recovered by enhanced oil recovery techniques.
It has long been recognized that the major factors which influence the amount of oil recovered by enhanced oil recovery techniques include the relative mobility of the reservoir oil and injected fluid, the wettability characteristics of the rock surfaces within the reservoir and the interfacial tension between the injected fluid and the reservoir oil.
Obviously, if plug-type flow of oil and displacing fluid from injection wells to production wells could be accomplished substantial amounts of the oil in place could be displaced. However, this is generally not accomplished because of the fact that most displacing fluids will travel faster through the reservoir than the oil because of adverse mobility ratios. While a rather simplistic explanation, the relatively low viscosity of gases, as opposed to the oil, causes the gas to follow paths of least resistance, with the result that the gas will channel through fractures and fissures, selectively pass through zones of higher permeability and in general contact a small area of the reservoir in passing from the injection well to the production well. In addition, gravity segregation of the injected gas and the oil causes the gas to rise to the top of the reservoir where it tends to ride over the top of the oil bank. Accordingly, while gases such as natural gas and air are usually readily available and relatively inexpensive, they are also relatively inefficient as displacing media under ordinary conditions. In addition, one must also consider the cost of compressing the gas to a pressure sufficient for displacement of the oil. On the other hand, liquids have a more favorable mobility ratio with respect to reservoir oil due primarily to their greater viscosity. Consequently, conventional water injection or waterflooding has been the most widely practiced enhanced oil recovery technique. However, the mobility ratio between water and reservoir oil is still generally poor. Accordingly, numerous modifications of conventional waterflooding have been proposed to overcome this problem. These include thickening the water with various materials, such as polymers, forming viscous water-oil emulsions by the use of surfactants, etc. Obviously, these thickening or emulsifying materials are expensive and cannot be used throughout the entire waterflood. Hence the thickening agent or emulsion is utilized only in that portion of the water in contact with the oil. An alternative is the injection of a small slug of polymer, generally having a viscosity greater than the viscosity of the oil, at the contact between the polymer and the oil, and a terminal viscosity, at the contact with the water, which is near that of the viscosity of water. Such graded concentration is usually logarithmic, from the viscosity of the reservoir oil to the viscosity of the water. In other variations, a thickening or viscosifying agent is preceded by one or more other displacing media and followed by water.
The wettability characteristics of the rock surfaces also affect displacement of oil by water. If the rock surfaces are oil wet, substantial amounts of the oil will adhere to the rock surfaces and resist displacement by the water. If the oil wettability of the rock surfaces can be altered either by decreasing the oil wettability or even reversing the wettability, to render the rock surface water wet, substantial improvement in oil displacement by water can be attained. Such reduction of oil wettability or reversal of wettability can also be accomplished by the utilization of surfactants. However, such surfactants are expensive and therefore must be utilized in limited quantities, generally as a slug ahead of a water drive.
The interfacial tension between a displacing fluid and reservoir oil is primarily dependent upon the ability of the two materials to mix. As a result miscible displacement techniques have been developed. For example, if natural gas is compressed to a sufficiently high pressure, usually above about 3000 psi, the gas can be rendered miscible with the reservoir oil. However, in some cases, if the miscibility pressure is too high to be practical or the reservoir cannot withstand pressures of this magnitude, this process cannot be used. In addition, the additional compression cost also adds to the cost of the project. Where applicable, however, this technique has proven quite effective. Similarily, at lower pressures, carbon dioxide can be rendered miscible with reservoir oils and miscible displacement can be carried out by displacing the oil with carbon dioxide. In addition to the advantage of the lower miscibility pressure, carbon dioxide has the advantage of a relatively high solubility in water. Consequently, techniques have been proposed in which a slug of carbon dioxide is followed by water or the carbon dioxide is dissolved in the water. At still lower pressures ethane and propane and mixtures thereof can be made miscible with reservoir oil. However, these materials, particularly propane, are expensive relative to the value of the oil displaced and accordingly can not be utilized in unlimited amounts. As a result the "propane slug process" has been developed in which a slug of propane is driven through the reservoir by gas, usually natural gas, under conditions such that the propane is miscible with the oil being displaced and with the driving gas. Again, while this technique is effective in appropriate reservoirs, utilization of gases as the drive fluid interjects the above-mentioned problems of mobility. Finally, under certain conditions, surfactants can be utilized in the miscible displacement of oil. At this point it should be recognized that the terms "miscible" and "miscibility", as they relate to enhanced oil recovery techniques, have been somewhat misused, for example by the use of terms such as "partial miscibility". However, what is generally meant by such terms is that one fluid is partially soluble in the other. Consequently, a more accurate definition of "miscible" or "miscibility", and the definition which will be utilized herein, is that the two fluids in question are mixable with each other in all proportions and of "solubility", where there is a limit to the amount of a material which is soluble in or will mix with a fluid. While miscibility between the reservoir oil and the displacing fluid can be said to be ideal to the extent that the oil-water interfacial tension is minimal, it is not necessary to obtain miscibility in order to reduce the oil-water interfacial tension and substantially improve displacement of oil by the drive fluid. Significant lowering of oil-water interfacial tension can be accomplished by the utilization of surfactants and highly effective immiscible displacement can be attained.
It is obvious from the above that the utilization of surfactants in enhanced oil recovery techniques has numerous advantages over the other techniques discussed. As previously indicated, the surfactant reduces the interfacial tension between a surfactant solution and reservoir oil and alters the oil wettability of the rock surfaces, thus substantially improving displacement of the oil. Secondly, since the surfactant solution is a liquid, it can be driven by water and the disadvantages of unfavorable mobility ratios, which are present when gases are used as drive fluid, are significantly reduced. Finally, enhanced oil recovery techniques utilizing surfactants can be utilized in reservoirs which have already been subjected to other recovery techniques, particularly where the reservoir has been produced to its economic limits by waterflooding. As a result, a substantial amount of research has been carried out in developing a wide variety of techniques utilizing surfactants and in improving the basic forms of these techniques. As previously indicated, because of the relative cost of surfactants, the surfactants are generally utilized in small amounts or in slug type operations in which the surfactant solution is driven through the reservoir by water.
The most basic of the surfactant techniques involves the injection of an aqueous surfactant solution, simply to reduce the oil-water interfacial tension. Such techniques are often referred to as "low tension waterflooding" techniques. Today one of the most promising low tension waterflooding tehniques involves the injection of aqueous solutions of petroleum sulfonates, having a predetermined equivalent weight range, under controlled conditions of salinity. This basic technique is further improved by sequential injection of a protective slug, the surfactant slug, a mobility control slug and finally water. The protective slug is an aqueous solution of sodium chloride which is injected in order to displace reservoir water ahead of the subsequently injected surfactant slug. The protective slug is usually substantially free of divalent ions which would tend to precipitate the subsequently injected surfactant. The surfactant slug comprises an aqueous solution of petroleum sulfonates and contains sodium chloride in a concentration, typically between about 1.0 to 7.0 weight percent, which will promote the desired low interfacia between the injected water and the reservoir oil. The subsequently injected mobility control slug is a thickened water slug containing a viscosifier or thickening agent, such as a water soluble biopolymer or polyacrylamide. The mobility control slug is preferably of logarithmically graded concentration in order to provide an initial viscosity greater than the viscosity of the reservior oil and a terminal viscosity near that of water. Finally, the driving fluid may be water from any source, but is usually brine present in the reservoir with the oil. In addition to petroleum sulfonates, a wide variety of synthetic sulfonates and complex sulfonates derived from either petroleum or synthetic sources have been proposed to further improve the process and overcome other problems which exist in certain reservoir environments.
As previously indicated, surfactants may be utilized under conditions to produce miscible or immiscible displacement of the oil. In addition, such surfactants have been used in systems which do not form microemulsions and those which do form microemulsions. In recent years considerable research has been devoted to the latter systems.
The microemulsions which have been proposed have been selected from compositions in the single phase region of a ternary diagram. Such microemulsion systems can be either oil-external microemulsions or water-external microemulsions. When such microemulsion systems are used, it is believed that the initial stages of oil recovery involve an efficient miscible displacement with subsequent immiscible displacement, upon the breaking down of the microemulsion into multiple phases due to dilution of the microemulsion with crude oil and reservoir water at its leading edge and dilution with the aqueous drive fluid at its trailing edge. Hence, optimization of such microemulsion surfactant systems is approached in terms of minimization of the multiphase region in the phase diagram so as to prolong miscible displacement with low interfacial tensions in the multiphase regions to thereby enhance immiscible displacement. From a practical standpoint, however, the development of effective microemulsion systems which can economically recover oil from a subterranean formation suffers from certain drawbacks in that it is difficult to maintain miscible displacement and it is difficult to obtain the low interfacial tensions necessary to provide effective immiscible displacement after miscible displacement ceases.
Surfactant systems have been developed which form microemulsions on contact with the reservoir oil. For example, U.S. Pat. No. 3,373,809 discloses recovering oil through the formation of a microemulsion formed in situ by injecting a surfactant system. This patent is based on the formation of a single phase microemulsion system with the reservoir oil by injecting a surfactant system to form the microemulsion system in situ. However, in order to achieve the desired results, extremely high concentrations of surfactant must be utilized. Such quantities of surfactant are usually in excess of about 7% to 15% by weight so as to provide a composition within the single phase region of a ternary diagram and, as such, can easily exceed the value of the oil recovered. Accordingly, it is becoming well recognized that it is impractical from an economic standpoint to maintain such a highly concentrated surfactant composition in the reservoir, which will remain effectively miscible throughout the lifetime of the operation, as proposed by the above patent and others.
Recent work has led to the suggestion of injecting microemulsion systems wherein the microemulsion phase is immiscible with the resident fluids in the reservoir. For example, U.S. Pat. No. 3,885,628 proposes to form a multiphase microemulsion system above ground by mixing oil, brine and surfactant and injecting at least the immiscible microemulsion phase. In some cases this patent suggests injecting one or more of the other phases, which exist in equilibrium with the microemulsion phase along the immiscible microemulsion phase. Later work, as set forth in U.S. Pat. No. 3,981,361, describes procedures for producing surfactant systems above ground are injected as an immiscible microemulsion. In this case emphasis is placed on the injection of the single immiscible surfactant-rich microemulsion phase. Also, U.S. Pat. No. 3,938,591 discusses the injection of immiscible microemulsion systems which resist uptake of oil and water into the immiscible microemulsion phase. In the last three techniques described, there is the obvious disadvantage of requiring the injection of a composition containing substantial amounts of oil which, of course, adds to the cost of the injected composition. In addition, there is the problem of achieving the optimum system for a given oil, since it turns out that different oils behave differently.
In order to overcome the above-mentioned and other difficulties incountered in the prior art use of surfactants in oil recovery, U.S. Pat. Nos. 4,079,785 and 4,125,156, which are incorporated herein by reference, disclose that an effective immiscible surfactant drive can be carried out by injecting a slug of surfactant solution comprising a surfactant, an electrolyte, water and, optionally, a cosurfactant to form a multiphase system in situ in the reservoir which comprises; at least two different regions, for example, an oil-rich region and a microemulsion region. The latter patent points out that best results are obtained when three different multiphase regions are formed, namely, a microemulsion, in equilibrium with an oil phase, a microemulsion in equilibrium with both an oil phase and a water phase and a microemulsion in equilibrium with a water phase. It is pointed out in this patent that among the variables which affect the three-phase region in which a particular system will partition are salinity, oil type, surfactant average equivalent weight, cosurfactant type and temperature. The patent also goes on to point out that, if all variables are fixed except the salinity, the system will shift from a microemulsion in equilibrium with an oil phase to a microemulsion in equilibrium with both an oil phase and a water phase to a microemulsion system in equilibrium with a water phase, as the salinity increases from zero. Finally, the patent sets forth a simple procedure which can be carried out in a laboratory to establish the system of water, electrolyte, surfactant and, optionally, cosurfactant and the proportions thereof which will be most effective for enhancing oil recovery when injected into the reservoir of interest.
While recent emphasis has been placed upon the use of petroleum sulfonates in surfactant waterflooding, numerous other surfactants have been proposed for use. For example, long chain organic acids, such as oleic, palmitic and stearic acids and the corresponding soaps have been suggested. Likewise sodium salts of so-called "tar acids", formed by adding to water-soluble tar acids, of the acid wash in petroleum refining, the alkaline wash liquids from the purification of crude oil fractions. Obviously, the latter proposal constitutes an effort to reduce the cost of the surfactant.
Also, while the previously mentioned surfactants are relatively inexpensive and the amounts utilized are small compared with the amount of drive water injected, the volume of surfactant necessary makes the cost of the surfactant a major factor. Consequently, a number of techniques have been proposed for reducing the cost of the surfactant.
One such technique is referred to as "caustic" or "alkaline" waterflooding. In this technique, an aqueous solution of an alkali metal or ammonium hydroxide or carbonate is injected into the reservoir in order to neutralize organic acids present in the reservoir oil and produce the corresponding alkali metal or ammonium salts. Thus, the surfactant is formed in situ. Alkaline waterflooding has been proposed in various recovery mechanisms to lower the interfacial tension between the reservoir oil and the injected water, to alter or even reverse the wettability of the reservoir rock or for the purpose of mobility control by the formation of a relatively viscous oil and water emulsion. In a variation of this technique, an aqueous alkaline solution is employed in which the alkalinity and monovalent salt salinity of the solution are controlled within defined ranges in order to result in low oil-water interfacial tensions which enhance the displacement of the oil. A thickened water slug may then be used for the purpose of mobility control following the injection of the alkaline solution.
The relative efficiency of an alkaline waterflood depends to some extent upon the total acid content of the reservoir oil. Accordingly, in some cases, insufficient naturally-occurring organic acids are present. Therefore variations of this procedure have been proposed in which air, peroxides or other oxidizing agents are injected into the reservoir in order to oxidize certain constituents of the oil in situ and form additional organic acids. Alternatively, a preoxidized oil bank may be injected or high molecular weight acids may be added to an injected oil bank. In any event, the aqueous alkaline solution is then injected in order to form the sodium salts of the naturally occurring organic acids, the added acids and/or those formed from the constituents of the oil in situ.
In most of these techniques the oxidation is inefficient, great care is required in the handling and use of oxidizing agents and most of the oxidizing agents are expensive to prepare.
Another technique for reducing the cost of surfactants and one which can be utilized where insufficient naturally-occurring organic acids are present in the reservoir oil, is the extraction of organic acids from materials containing the same, particularly from the reservoir oil itself, at the surface of the earth followed by neutralization to form salts or injection of the acid followed by injection of an aqueous alkaline solution to form the salts in situ. This surface extraction of acidic materials is, of course, advantageous to the extent that extracted acids can be accumulated to thereby inject the optimum amount into the formation rather than relying upon the acid content of the oil volume immediately adjacent the injection well. However, present techniques for extracting the acids from the acid-containing material leave much to be desired. One technique involves passing the oil through a solid ion exchange agent which adsorbs the acids by ion exchange. While high percentages of the acid present in the oil can be extracted by this technique, it is expensive and cumbersome. Solid ion exchange agents, usually used, are expensive and lose their effectiveness in time and as a result of the presence of contaminating ions in the oil. In addition, once the acids are adsorbed by the ion exchange resin they must be removed by passing an eluent through the resin to reverse the exchange and elute the acids therefrom. When the exchange capacity of the resin deteriorates it is also necessary to regenerate the resin and often precondition the resin, by an ion exchange mechanism, for further use. Eventually, however, where regeneration and renewal of the exchange capacity are ineffective the resin must be replaced. In another standard technique the oil is extracted with an aqueous solution of sodium hydroxide or an aqueous ethanol solution of sodium hydroxide. While this liquid-liquid extraction technique is simple and relatively inexpensive, the recovery of acids is extremely low, particularly by comparison to the ion exchange technique.
Along the same lines it has also been proposed that components of the oil be converted to sulfonate-type surfactants by treatment with formaldehyde and an alkaline sulfite and the thus recovered surfactants thereafter injected into the reservoir.
It is apparent from the above that present day techniques for the recovery of petroleum from subsurface earth formations utilizing surfactants are fraught with many problems, including the manufacture of such surfactants, the cost for such surfactants, the handling of materials for preparing surfactants and difficulties in the transportation and handling of such materials and/or the resultant surfactants, etc., all of which ultimately lead to high costs and inefficiencies.
As it will appear from the following discussion, many of the same problems encountered in the recovery of petroleum, as well as additional problems, are encountered in the recovery of metallic mineral resources.
Numerous metallic mineral resources are present in subsurface earth formations in very small quantities which make their recovery extremely difficult. However, in most instances, these minerals are also extremely valuable, thereby justifying efforts to recover the same. An example of one such mineral is uranium. However, numerous other valuable minerals, such as vanadium, thorium, gold, rare earth metals, etc., are also present in small quantities in subsurface formations, alone and quite often associated with uranium. Consequently, the recovery of such minerals is fraught with essentially the same problems as the recovery of uranium and, in general, the same techniques for recovering uranium can also be utilized to recover such other mineral values, whether associated with uranium or occurring alone.
Uranium occurs in a wide variety of subterranean strata such as granites and granitic deposits, pegmatites and pegmatite dikes and veins, and sedimentary strata such as sandstones, unconsolidated sands, limestones, etc. However, very few subterranean deposits have a high concentration of uranium. For example, most uranium-containing deposits contain from about 0.01 to 1 weight percent uranium, expressed as U.sub.3 O.sub.8 as is conventional practice in the art. Few ores contain more than about 1 percent uranium and deposits containing below about 0.1 percent uranium are considered so poor as to be currently uneconomical to recover unless other mineral values, such as vanadium, gold and the like, can be simultaneously recovered.
There are several known techniques for extracting uranium values from uranium-containing materials. One common technique is roasting of the ore, usually in the presence of a combustion supporting gas, such as air or oxygen, and recovering the uranium from the resultant ash. However, the present invention is directed to the extraction of uranium values by the utilization of aqueous leaching solutions. There are two common leaching techniques for recovering uranium values, which depend primarily upon the accessibility and size of the subterranean deposit. To the extent that the deposit containing the uranium is accessible by conventional mining means and is of sufficient size to economically justify conventional mining, the ore is mined, ground to increase the contact area between the uranium values in the ore and the leach solution, usually less than about 14 mesh but in some cases, such as limestones, to nominally less than 325 mesh, and contacted with an aqueous leach solution for a time sufficient to obtain maximum extraction of the uranium values. On the other hand, where the uranium-containing deposit is inaccessible or is too small to justify conventional mining, the aqueous leach solution is injected into the subsurface formation through at least one injection well penetrating the deposit, maintained in contact with the uranium-containing deposit for a time sufficient to extract the uranium values and the leach solution containing the uranium, usually referred to as a "pregnant" solution, is produced through at least one production well penetrating the deposit.
The most common aqueous leach solutions are either aqueous acidic solutions, such as sulfuric acid solutions, or aqueous alkaline solutions, such as sodium carbonate and/or bicarbonate.
While aqueous acidic solutions are normally quite effective in the extraction of uranium values and act quite rapidly in the extraction of the uranium values, the volumes of acid consumed are usually quite high, thus making the use of aqueous acidic solutions relatively expensive. In addition, aqueous acidic solutions generally cannot be utilized to extract uranium values from ores or in situ from deposits containing high concentrations of acid-consuming gangue, such as limestone. While aqueous alkaline leach solutions are applicable to all types of uranium-containing materials and are less expensive than acids, the quantities of alkaline material necessary also make the use of these solutions expensive.
The uranium values are conventionally recovered from acidic leach solutions by techniques well known in the mining art, such as direct precipitation, selective ion exchange, liquid extraction, etc. Similarly, pregnant alkaline leach solutions may be treated to recover the uranium values by contact with ion exchange resins, precipitation, as by adding sodium hydroxide to increase the pH of the solution to about 12, etc.
As described to this point, the extraction of uranium values is dependent strictly upon the economics of mining versus in situ extraction and the relative costs of acidic leach solutions versus alkaline leach solutions. However, this is an oversimplification, to the extent that only uranium in its hexavalent state can be extracted in either acidic or alkaline leach solutions. While some uranium in its hexavalent state is present in mined ores and subterranean deposits, the vast majority of the uranium is present in its valence states lower than the hexavalent state. For example, uranium minerals are generally present in the form of uraninite, a natural oxide of uranium in a variety of forms such as UO.sub.2, UO.sub.3, UO.U.sub.2 O.sub.3 and mixed U.sub.3 O.sub.8 (UO.sub.2.2UO.sub.3), the most prevalent variety of which is pitch blende containing about 55 to 75 percent of uranium as UO.sub.2 and up to about 30 percent uranium as UO.sub.3. Other forms in which uranium minerals are found include coffinite, carnotite, a hydrated vanadate of uranium and potassium having the formula K.sub.2 (UO.sub.2).sub.2 (VO.sub.4).sub.2.3H.sub.2 O, and uranites which are mineral phosphates of uranium with copper or calcium, for example, uranite lime having the general formula CaO.2UO.sub.3.P.sub.2 O.sub.5.8H.sub.2 O. Consequently, in order to extract uranium values from mined ores and subsurface deposits with aqueous acidic or aqueous alkaline leach solutions, it is necessary to oxidize the lower valence states of uranium to the soluble, hexavalent state.
Combinations of acids and oxidants which have been suggested by the prior art include nitric acid, hydrochloric acid or sulfuric acid, particularly sulfuric acid, in combination with air, oxygen, sodium chlorate, potassium permanganate, hydrogen peroxide and magnesium dioxide as oxidants. Alkaline leachants or oxidants heretofore suggested include carbonates and/or bicarbonates of ammonium, sodium or potassium in combination with air, oxygen or hydrogen peroxide as lixivants. However, sodium bicarbonate and/or carbonate have been used almost exclusively in actual practice. The most prevalent oxidant utilized in commercial operations is air for economic reasons. However, certain difficulties are encountered in the use of air to the extent that insufficient air can be dissolved in the leach solution at atmospheric pressure, thereby rendering the extraction process rather inefficient.
Hydrogen peroxide has been found to be a highly effective oxidant in either acidic or alkaline leach solutions but the many problems associated with such use tend to negate its advantages. While pure solutions of hydrogen peroxide, completely free of contaminants, are highly stable, such pure solutions are expensive and their purity almost impossible to maintain. On the other hand, concentrated solutions are highly toxic and strong irritants. In addition, in solution, hydrogen peroxide decomposes into water and oxygen, which decomposition is accelerated by the presence of impurities. Consequently, in using hydrogen peroxide as an oxidant for the recovery of uranium, the addition of hydrogen peroxide to the leach solution, prior to use, will result in rapid deterioration, particularly since such decomposition is accelerated by alkalis, and, hence, much more hydrogen peroxide than is necessary must be utilized even in the extraction of mined ore. This problem is even more exaggerated when hydrogen peroxide is utilized in leach solutions for in situ recovery of the uranium from subsurface earth formations. Since solid hydrogen peroxide is explosive, there is always the danger of fire and explosion in the event attempts are made to utilize the same in this form, as well as in solution.
As previously indicated, the expense of utilizing hydrogen peroxide is a major factor. This is due to the complexity of commercial methods for manufacture and separation of the hydrogen peroxide. One common method is the autooxidation of an alkylanthrahydroquinone, such as the 2-ethyl derivative, in a cylic continuous process in which the quinone the oxidation step is reduced to the starting material by hydrogen in the presence of a supported paladium catalyst. A second technique involves electrolytic processes in which aqueous sulfuric acid or acidic ammonium bisulfate are converted electrolytically to the peroxybisulfate which is then hydrolyzed to form hydrogen peroxide. A third method is the autooxidation of isopropyl alcohol. Of these techniques, the first mentioned is the most widely utilized. It is also known that hydrogen peroxide can be produced as a by-product by the autooxidation of paraffinic hydrocarbons, such as propane, to produce olefins. Efforts have also been made to maximize the production of hydrogen peroxide in this type reaction. However, no known commercial process utilizes this type of reaction and, hence, it has remained a laboratory curiosity.
The above discussion illustrates that the recovery of metallic mineral resources from subsurface earth formations is also subject to a number of problems, including cost of materials, the handling, transport and use of such materials, particularly oxidizing agents and other problems previously mentioned in connection with the recovery of petroleum, all of which again result in high costs and inefficient operations.